The present invention relates to methods, compositions, systems, and devices useful in treating subterranean formations and, more particularly, to consolidating potentially relatively unconsolidated portions of subterranean formations and minimizing the flowback of unconsolidated particulate materials such as formation fines and sand (referred to collectively herein as “particulate migration”) over long intervals. More specifically, the present invention relates to methods for applying consolidating agent systems over at least a portion of a long interval in a subterranean well bore that may be horizontal, vertical, deviated, or otherwise nonlinear.
A type of particulate migration that may affect fluid conductivity in a subterranean formation is the flowback of unconsolidated particulate materials (e.g., formation fines, proppant particulates, etc.) through the conductive channels in the subterranean formation, which can, for example, clog or impair the conductive channels and/or damage the interior of the formation or equipment. Another issue that can negatively impact conductivity and further complicate the effects of particulate migration is the tendency of mineral surfaces in a subterranean formation to undergo chemical reactions caused, at least in part, by conditions created by mechanical stresses on those minerals (e.g., fracturing of mineral surfaces, compaction of mineral particulates, etc.). These reactions are referred herein to as “stress-activated reactions” or “stress-activated reactivity.” The term “modifying the stress-activated reactivity of a mineral surface” and its derivatives as used herein refers to increasing or decreasing the tendency of a mineral surface in a subterranean formation to undergo one or more stress-activated reactions, or attaching a compound to the mineral surface that is capable of participating in one or more subsequent reactions with a second compound.
There are several techniques to control particulate migration and modify the stress-activated reactivity of mineral surfaces in a formation, some of which may involve the use of consolidating agent systems. The term “consolidating agent” or “consolidating agent system” (the terms may be used interchangeably) as used herein includes any compound or combination of compounds that is capable of reducing particulate migration in a subterranean formation and/or modifying the stress-activated reactivity of subterranean surfaces in a subterranean formation. Consolidating agent systems are thought to enhance or, in some instances, alter a subterranean formation's mechanical properties to prevent or reduce the potential for particulate migration and stress-activated reactivity, and perhaps providing relatively small increases in mechanical strength.
One method used to modify particulate migration parameters in some subterranean formations involves consolidating unconsolidated portions of subterranean formations into relatively stable permeable masses by applying a consolidating agent system to an unconsolidated portion of the formation. One example of such a method is applying a curable resin to a portion of a subterranean zone, followed by a spacer fluid, and then a catalyst that can activate the resin. Another example of such methods involves applying a tackifying composition (aqueous- or non-aqueous-based) to a portion of the formation in an effort to reduce the migration of particulates therein. Whereas a curable resin composition may produce relatively hard masses, the use of a tackifying composition produces more malleable consolidated masses.
While previously known consolidating agent systems are thought to be generally effective over short productive intervals (e.g., less than about 30 feet), effective placement of consolidation chemicals over heterogeneous long intervals has often proven time-consuming and difficult. The term “long interval” as used herein refers to an open hole section of about 30 feet or more in a subterranean well bore penetrating a subterranean formation. For example, some long vertical or deviated well intervals may be about 30 feet to about 100, 250, or 500 feet, and some long horizontal intervals may be about 500 feet to about 10,000 feet. Some may be longer.
Wells with longer production intervals are typically completed using cased hole or open hole gravel pack techniques. Such gravel pack techniques may involve placing a sand control screen to provide secondary filtration and mechanical support and a layer of uniformly graded gravel or sand between the formation and screen to act as a primary filtration layer, thus preventing particulate migration. These conventional gravel pack completions require large bore completions because of the need to install both screens and gravel, requiring long and complex pumping operations, which take additional rig time. The placement of the gravel in long horizontal intervals can also be complex if there are borehole quality or fluid loss problems. In many cases, alternate path technologies are used where additional space is required to attach shunt tubes on the outside of the screen to act as transport tubes to ensure complete gravel placement.
If a consolidating-agent-type of system is chosen, typical systems for placing chemicals over a long production interval may involve selective injection-type tools where a short section of the borehole is isolated, then treated with consolidating agents. The tools are then moved to the next interval and the process is repeated until the entire reservoir section has been treated. Such treatments may be referred to as multiple stage treatments. For long intervals, this process can be very time-consuming and complex as each injection step will require multiple fluid stages. Further, it is necessary to keep very accurate track of fluids in the tubulars through the entire treatment, which can be time-consuming and difficult. Such stepped treatments may take several days of rig time to complete. A single stage operation (i.e., one that does not require such multiple fluid stages to place the consolidating agent system over a long interval) could have fewer complications and take less rig time.
Filter cake (e.g., the residue deposited on the walls of a well bore by a fluid, usually a slurry, such as a drilling fluid) may control fluid loss and minimize formation damage during drilling and completion. Typical filter cakes may comprise bridging agents and in some instances, polymeric components, depending on the composition of the fluid used to form the filter cake. In typical sand control completions, a filter cake may stay intact until installation of a sand control completion.
While filter cakes may be beneficial, it is generally thought to be beneficial to remove filter cakes from producing zones once the well is placed into production. Generally, a filter cake is removed mechanically or chemically, or by allowing it to degrade with produced fluids. One method for degrading filter cakes from producing formations involves including an acid-soluble particulate bridging agent for bridging over the formation pores in the drilling, fracturing, gravel transport, or other servicing fluid that forms the filter cake. Such an acid-soluble filter cake could then be degraded by placing a strong acid solution in contact with the filter cake and allowing that solution to remain in contact for a period of time sufficient to degrade the filter cake by at least interacting with the acid-soluble bridging agents.
One consideration in degrading a deposited filter cake from a subterranean well bore formation often involves the timing of such degradation. For instance, in situations where sand control of the formation is a concern, a filter cake is thought to offer some degree of control over unconsolidated particulates in the subterranean formation while placing the gravel pack. For example, if the filter cake is removed prior to gravel packing, the unconsolidated particulates may migrate, and as a result, well bore stability problems may arise that may cause collapse of the well bore, thus preventing the installation of a gravel pack. Additionally, loss of filter cake integrity can also result in severe losses of fluid during completion operations or gravel displacement, creating well control problems or the inability to effectively place gravel across the entire interval. While installing the screen and placing the gravel before degrading the filter cake may help control unconsolidated particulates, prevent undesirable losses of well bore fluids, and maintain borehole stability, as a result the filter cake itself may be more difficult to degrade. In such instances, the screen and gravel may represent a physical barrier between the filter cake on walls of the well bore and the filter cake degradation fluid used to degrade the filter cake.
An additional problem that may affect long production intervals that often needs to be managed is the presence of shale. Shale can be problematic because it can generate a large volume of fines. Oftentimes, it may be desirable to physically isolate portions of the subterranean formation that contain shale to prevent the production of such fines. In some instances, shale may be isolated with blank pipe (e.g., pipe that does not comprise slots or other holes on its exterior surface oriented to the well bore walls). Exposed shale may be hydraulically isolated by placing blank pipe across these intervals and isolating the annulus using open hole packers. Conventional mechanical, hydraulic, hydrostatic, inflatable, or swelling elastomer packers may provide annular isolation for this purpose. Some examples of open hole packers include WIZARD® III Packer and SWELLPACKER™, both of which are available from Halliburton Energy Services, Inc. in Carrollton, Tex.
Effective treatment of long intervals can be further complicated by variable reservoir properties such as porosity, permeability, and pore pressure. The term “reservoir” as used herein refers to a subsurface body of rock having sufficient porosity and permeability to store and transmit fluids such as gas, oil, or water. For instance, a long interval may include variable high permeability portions. In some situations, high permeability portions may act as thief zones taking the bulk of the treatment fluids, where low permeability, higher pressured zones may not accept any of the treatment fluids. Chemical diversion techniques are often used in stimulation treatments and are focused on plugging the high perm zones to help force fluid flow into the low perm zones. Uniform placement of treating fluids under these conditions and using these solutions can be difficult and unreliable. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation performed in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action. As used herein, the term “treatment fluid” refers to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof.